Subterranean formations are typically characterized as having a plurality of production zones. During production of fluids from the well, it usually is desirable to establish communication with selected zones to prevent the inadvertent flow of fluids into a non-productive zone or a zone of diminished interest. Selective stimulation becomes pronounced as the life of the well declines and productivity of the well decreases.
Typically, a large amount of water is used during a stimulation operation. For instance, during a hydraulic fracturing operation, water may be pumped into fractures at pressures exceeding 3000 psi and at flow rates exceeding 85 gallons per minute. A horizontal well with a 4,500 foot lateral bore may require about 4 to 5 million gallons of water. The fluid which returns to the surface may be flowback water, produced water or produced oil or gas.
Flowback water typically is characterized by high salinity and dissolved solids. Included as dissolved solids are salts which are recovered from the formation. Such salts increase the natural salinity of water pumped into the well. Flowback water also often contains the same chemicals which are pumped into the well and often contains contaminants originating from rock formation water.
Produced water contains clay, dirt, metals and chemicals that may have been added during the treatment operation. The amount of produced water brought to the surface may be very high. For instance, an additional 10,000 to 30,000 bbl of produced water may flow for up to two years. The point at which flowback water becomes produced water is often difficult to distinguish, yet may be discerned from the chemistry of flowback water versus naturally occurring water produced by the formation.
Inefficiency in production often is the result of precipitated deposits which form in the formation during an operation. For instance, it is well known that undesirable deposits can precipitate from saturated oilfield waters in an oil or gas well. Such deposits lead to a restriction in production piping and result in plugging of reservoir flow paths. For instance, common mineral scales such as calcium carbonate, calcium sulfate, or barium sulfate can precipitate from produced water, precipitate from saturated oil or gas wells and create blockages in flow paths, especially in production tubulars such as well tubing and flow lines.
Reservoir Monitoring refers to the gathering and analysis of information from reservoirs during production. Such monitoring is used to assess the productivity of zones from which fluids are being produced. In addition, reservoir monitoring provides an understanding of the dynamics of hydraulic fracture placement and subsequent fluid flowback and clean up.
In the past, methods of monitoring produced fluids have used tracers (such as fluorinated benzoic acids) which have been placed in strategic areas within the well. See, for instance, U.S. Pat. Nos. 3,991,827; 4,008,763; 5,892,147 are U.S. Pat. No. 7,560,690. Such methods typically are only useful for a short time following placement of the tracer within the well. Further, most monitoring methods are restricted to near-wellbore production activity, are cumbersome and are not particularly cost effective. Alternatives have therefore been sought.
In addition, alternatives have been sought which more efficiently treat reservoirs by inhibiting the formation of undesirable deposits.